The presence of low-temperature sedimentary basins in the midcontinent of the United States has spurred interest in utilizing geothermal energy from deep saline aquifers to reduce the use of fossil fuels for direct heating and cooling. However, developing geothermal resources is hindered by high capital cost and risks associated with the feasibility of extracting the resources. To reduce risk and uncertainty in estimating the extractable energy from the Mt. Simon Sandstone (MSS) in the Illinois Basin (ILB), a modeling workflow was developed to assess feasibility of delivering geothermal energy using a two-well (doublet) system. The proposed Deep Direct-Use (DDU) Geothermal Energy System (GES) would directly supply geothermal energy to heat agricultural research facilities (ARF) at the University of Illinois at Urbana-Champaign (U of IL). The total amount of geothermal energy that will be transported to the ground surface was determined by modeling temperature changes from the MSS reservoir to the surface. A geocellular model informed the reservoir modeling, which was developed with hydraulic and thermal properties measured in boreholes drilled within a 36-square mile (93 km2) area of around the U of IL. Geothermal reservoir simulations were performed to estimate maximum rates for extracting and injecting the geothermal fluid and evaluate the sensitivity of reservoir temperature distribution with changing the well spacing, extraction and injection rates, and seasonal (ambient ground surface) temperatures. Reservoir modeling results predict maximum extraction and injection rates that greatly exceed the required flow rate of 954 m3 [6,000 bbl/d] to meet the ARF heating ~2 MMBtu/hour–-and maintain a temperature difference of 11 °C (20 °F) between the extracted and injected fluid. A 2-D, axisymmetric wellbore model extending from the ground surface to the bottom of the MSS (~1,751 m [5,745 ft] depth) was used to simulate temperature changes during extraction and injection. This model was calibrated to distributed temperature sensing (DTS) log from a CO2 storage well at the IBDP. The calibrated wellbore model was used to evaluate how variations in the extraction rate, wellbore insulation, and thermal properties of the wellbore materials (i.e., tubing, casing, cement) impact the temperature during extraction. Additionally, the effects of rate, tubing radius, and fluid temperature during injection were investigated. Wellbore modeling results indicated that installing a vacuum-insulated tubing or placing silicate foam around the extraction well tubing would preserve the heat stored in extracted geothermal fluid and limits the temperature change (loss) to

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